Process for recovering oil from underground reservoirs



July 3, 1962 B. T. WILLMAN 3,042,114

PROCESS FOR RECOVERING OIL. FROM UNDERGROUND RESERVOIRS Filed Sept. 29, 1958 FIG. 2

Berirom Thomas Willmon Inventor BW AH rney Unite States Patent 3 042,114 PROCESS FOR RIECOVERING OIL FROM UNDERGROUND RESERVOIRS Bertram T. Willman, Tulsa, Okla assignor to Jersey Production Research Company, a corporation of Delaware Filed Sept. 29, 1953, Ser. No. 764,102 4 Claims. (Cl. 16611) This invention pertains broadly to the recovery of petroleum from underground reservoirs. It pertains more especially to an improved method of secondary recovery in which a hot aqueous fluid is employed as the oil-driving medium. While useful in all types of oil reservoirs, the invention has particular application in those reservoirs which contain viscous crude oils-i.e., oils of about SO-centipoise viscosity or greater.

In View of the ever-increasing demand for oil, the petroleum industry is continuously in search of improved methods for recovering petroleum from underground reservoirs. Particularly in demand are improved methods of secondary recovery which may be applied to depleted reservoirs or to reservoirs that lack natural gasor waterdri-ve media. A wide variety of secondary recovery techniques has been suggested or tried to date, but none of the methods have been entirely or universally applicable. It has been particularly diflicult to find a method which is attractive for use in reservoirs that contain viscous crude oils.

Among the more promising methods that have been suggested or tried for the secondary recovery of oil from viscous oil reservoirs are those methods calling for the injection of steam or hot water within the reservoirs. In such methods, the hot water or steam is injected through one or more injection wells and forced through the reservoir by means of pressure.

In the case of the steam method, the leading portion of the steam condenses upon contacting the relatively cold reservoir rock and crude oil and forms a bank of hot water; and a temperature gradient is established within this bank. The reservoir oil which has been heated by the hot water bank experiences a decrease in viscosity and an increased mobility. The main body of steam following behind the bank of hot water drives both the hot water and the heated oil before it toward the production Wells. Ultimately, oil, hot water and steam are produced from the reservoir through the production wells. The process is continued until the production of oil is no longer economical.

The hot-water method of secondary recovery is somewhat similar to the steam method in that a body of hot water is moved through a reservoir so as to heat the reservoir and displace oil therefrom. The hot-water method is, however, materially different from the steam method in several respects. A major difference lies in the fact that greater flexibility in the selection of operating temperatures and pressures is possible vu'th the hotwater method than is possible with the steam method. For example, steam methods are limited practically at the present time to pressures of about 1800 psi. or less, whereas hot-water methods may be readily employed at pressures far in excess of this value. This means that the hot-water process, in general, may be applied more universally to relatively deep reservoirs than can the steam method.

A major disadvantage of both the steamand hot water-injection processes lies in the tremendous amounts of heat and fuel that they require. In this connection, it will be recognized that only a small part of the injected heat serves to heat oil, while the great bulk of the heat is consumed in heating the porous rock structure of the reservoir. It will also be recognized that substantial 3,042,114 Patented July 3, 1962 quantities of heat are lost to earth strata that surround the reservoir structure. The losses to the surrounding strata increase with the amount of time that the reservoir must be heated during the life of the process. Thus, while the hot waterand steam-drive processes both appear technically sound for use in oil reservoirs, they are still unsound economically in that their heat consumptions or losses are excessive.

In this connection, it is a general object of this invention to provide improvements in the secondary recovery methods which use hot aqueous driving media--i.e., hot water in liquid and/or vaporous form. More particularly, it is an object of the invention to reduce the heat requirements that presently accompany such processes and thereby to render the processes much more sound economically. It is a further object of the invention to provide a secondary recovery process which is far more effective and attractive for use in heavy-oil reservoirs than are processes which have been suggested heretofore in the art.

These and related objects of the invention will be expressly discussed or readily apparent from. the following description. The objects are realized in accordance with the invention by the following general procedure. The first step in the procedure consists of injecting a hot aqueous fluid into a reservoir through one or more injection wells. Any conventional floodingor well-pattern may be used, as the particular flooding pattern employed in any given instance forms no critical feature or aspect of this invention. The hot aqueous fluid may be steam or liquid water, depending upon whether the fluid is injected at a pressure equal to or greater than its saturation pressure. The temperature level of the steam or water is governed by the characteristics of each specific reservoir and the thermodynamic relationships for water.

Economics to a great extent control the selection on the proper temperature and reflect reservoir thickness, permeability, crude viscosity and gravity, reservoir temperature and depth, and other variables peculiar to a given reservoir. As a general rule, however, desirable temperatures will generally lie in the range of 350 F to 620 F.

In the case of steam, it is generally preferred that saturated steam ranging up to the maximum pressure consistent with steam-generated equipment and maximum over-burden weight be employed to reduce exploitation times and heat losses. Superheated steam may also be used, but there is little or no advantage in its use, due to the small amount of heat contained in the super-heat as compared to latent heat.

In those instances where hot waterrather than steam-is injected within a reservoir, it is preferred that it be injected at the maximum. pressure possible without causing fracturing or reservoir damage.

In ordinary practice, the quantity of hot aqueous fluid which is injected within a reservoir in practicing this invention should be at least sufficient to raise the temperature of the oil recovered thereby to the desired value at the end of exploitation. As will be recognized by those skilled in the art, the desired value ultimately obtained in any given reservoir will depend upon a number of factors. A major factor, however, will be the viscosity which the oil will possess at that temperature. Thus, the oil perme ability of a reservoir and the mobility of the oil within the reesrvoir (both relative to the water within the reservoir) have a very important bearing upon the effectiveness of water to displace oil from the reservoir. These are factors, however, that are conventionally applied to the study of petroleum reservoirs by those skilled in the art; and a lengthy discussion of their relative importance and application is not therefore considered to be necessary in this description. The present invention makes use of this technical knowledge, but it improves upon that the reservoir.

knowledge by making it possible to inject far less heated fluid than has heretofore been used.

Whereas the steamand hot water-injection processes of the prior art have continuously injected such fluids for the entire duration of a recovery operation, the present invention discontinues such injection at a time well before the end of the operation. The present invention thus avoids the very undesirable condition of leaving an entire reservoir heated to an extremely high temperature at the very moment when the last amount of recoverable oil has been obtained and the process terminated. Instead of continuing to inject hot aqueous fluid, the invention injects a gaseous, non-aqueous fluid following the hot aqueous fluid. The gas may have a temperature substantially less than that of the heated reservoir, as would commonly be the case after compression of the gas. Air, methane, natural gas, or other readily available materials substantially inert to petroleum under such conditions may be used.

The pressure of the gas injected within the second phase of this invention should not exceed a value about ten percent greater than the pressure of the reservoir. Indeed, it is preferred that the gas-injection pressure be not more than slightly greater than the reservoir pressure.

If the pressure within the heated portion of the reservoir is greater than the saturation pressure of water at the temperature of the heated portion (as would be the case when injecting hot water at a pressure greatly in excess of its vapor pressure), the pressure of the reservoir should be reduced to the vapor pressure of the water or less before injecting the gas. The manner contemplated for best effecting such pressure reduction lies simply in producing the reservoir through its production wells until the desired pressure level has been attained. Gas injection may be started thereafter.

Once gas injection is started, a process or mechanism is set up in which a bank or zone of heat is moved through a reservoir, displacing and carrying oil with it. Thus, as gas invades the hot reservoir, it displaces the previously injected steam or hot water therefrom. The gas becomes saturated with water vapor as it flows through the hot rock containing liquid water at high temperature. Water thereby evaporated saturates the incoming gas and cools the reservoir rock originally left hot by the hot injected aqueous fluid; and reservoir temperatures are reduced where such evaporation occurs at the tail end of the hot bank.

The water vapor-saturated gas passes through the hot portion of the reservoir; and, upon encountering cool rock, the water vapor is condensed from the gas. This condensation thereby heats rock ahead of the original hot zone. The gas, after losing almost all of its water vapor in this manner, continues to flow through the reservoir and is produced at the production well or wells.

To recapitulate, then, the process of the present inven tion is one in which a hot zone is created within a reservoir by injecting hot liquid water and/or steam within the reservoir. The pressure within the reservoir may be decreased as necessary to a value equal to, or less than, the saturation pressure of water within the heated zone. Gas is then injected into the reservoir, and the heated zone is progressively moved through the reservoir toward the producing well or wells.

The amount of hot liquid water or steam to be used in any given reservoir will vary somewhat, depending upon reservoir conditions, as noted earlier in this description. In general, however, the injection of hot aqueous fluid should be terminated when the amount injected contains suflicient heat to heat from 0.2 to 0.6 of each pattern bulk volume of the reservoir to the temperature of the injected fluid. In this connection, the term pattern bulk volume is the volume of the producing section of a reservoir which underlies the basic-or unitpattern of The term is derived from the practice within the petroleum industry to carry out producing operations within a reservoir by using particular well patterns. One very common such pattern is the so-called fivespot pattern. In this pattern, an injection well is located at the center of a square whose four corners are occupied by producing wells. The sum of the pattern bulk volumes within a reservoir is then the total exploited bulk volume of the reservoir. The determination of the total exploited bulk volume, as well as the individual pattern bulk volume, of a reservoir is a well-known procedure and obtained by conventional petroleum engineering techniques.

Although either hot liquid water or steam may be employed in the practice of this invention, it is preferred to use steam wherever possible and feasible. It is further preferred-and especially when steam is employed to inject cool liquid water prior to, simultaneously with, or intermittently with the driving gas. This additional water enables the process to operate in the most thermally efl lcient manner, it being desirable to cool the rock behind the heated zone back toward original reservoir temperature. For example, in the case where high-pressure steam is injected within a reservoir, the evaporation of some ten to fifteen pounds of water per cubic foot of steamed-out reservoir is generally required to restore the reservoir to near its original temperature.

Work with steam-injection processes has indicated that residual water saturations of one to four pounds of water per cubic foot of the net oil-bearing rock within a reservoir are left behind in the steamed-out portion. The term net Oil-bearing rock is intended to mean solely that portion of a reservoir which contains oil as distinguished from shale. This amount of water is con siderably less than that required to completely cool rock at the trailing edge of the steam Zone by Water evaporation into the gas injected subsequent to the steam. Accordingly, unless more water is supplied as just described, the rock will be left dry at a temperature somewhat lower than that of the injected steam, but still considerably above reservoir temperature. The additional injected water, however, avoids this condition by flowing ahead together with the injected gas to make up the difference between the residual water from the steam process and that required to further cool the rock by evaporation into the gas.

The quantities of water to be injected subsequent to the injection of steam (and prior to or simultaneously with the driving gas) may be readily ascertained as shown by the example of a reservoir heated to 620 F. by 1800 psi. steam. The residual water left by the steam and available for evaporation may be from about one to ten poundsper cubic foot of reservoir rock, depending upon such factors as the amount of shale, the porosity of the rock and shale, etc., known for any given reservoir. In such a reservoir, approximately fourteen pounds of water per cubic foot of reservoir rock must be evaporated to cool the rock at the trailing edge of the steam zone to a value of F. Consequently, if say only five pounds of residual water is left by the steam zone (as would be very reasonable for a sandstone material), then a gas such as methane and cool liquid water for evaporation may be injected in the ratio of say ten standard cubic feet of methane to nine pounds of water. This quantity of water evaporated into the gas will reduce the temperature of the reservoir rock to the desired level.

In addition to the water which must be injected with the driving gas in order to cool a reservoir rock down to a preselected temperature, further water should also be added as necessary to provide the rock behind the heated zone with adequate water permeability. In most instances, this further quantity of water will generally constitute about one to six pounds of water per cubic foot of cooled reservoir. Thus, in the example given above, the nine pounds of water supplied per cubic foot of rock for evaporation purposes should be increased by the number of pounds (determined from conventional relative permeability measurements and relationships) required to leave the cooled rock with a water saturation high enough so that water and gas may flow ahead in the desired proportions to the heated zone. Assuming the quantity of water for favorable permeability characteristics in the above example amounts to five pounds per cubic foot of cooled reservoir material, then nine plus five, or fourteen, pounds of water per cubic foot should be supplied, along with the driving gas.

The invention may be better understood by reference to the drawing in which FIGURE 1 illustrates a vertical section of a reservoir and the temperature profile therein as a bank of steam is injected into the reservoir.

FIGURE 2 illustrates the same reservoir and its temperature profile as gas is injected into the reservoir after the bank of steam.

Referring first to FIGURE 1, reservoir 12 in a section of earth 13 is penetrated by an input well and an output well 11. Steam has been injected through well 10 and has established two temperature zones in moving toward Well 11. Zone B is a gradient zone having temperatures ranging from the original temperature of the reservoir as typified by Zone A to the temperature of the injected steam as typified by Zone C. The nature of the temperature gradient in Zone B is more evident in the temperature profile presented in the lower portion of FIG- URE 1. Here, T indicates the temperature prevailing within Zone A-i.e., the original temperature of the reservoir. T on the other hand indicates the temperature of the injected steam. A thermal gradient from T to T eX- ists in Zone B. Zone A is essentially filled with liquid connate water, cool condensed steam, oil, and other natural reservoir fluids. Zone B contains condensate, connate water, oil, and other natural reservoir fluids. Zone C contains largely steam and residual oil, and condensate.

Turning next to FIGURE 2, the temperature conditions within the reservoir 12 are shown after a gas has been injected through well 10 following the injection of steam. In this instance, Zones B and C have advanced toward well 11; and another Zone D has been established. Zone D resembles Zone B in that it too possesses a thermal gradient caused by the vaporization of steam condensate and reservoir fluids into the injected gas. The resulting vapors are carried forward by the gas into the steam bank. If carried far enough, they are re-condensed at the leading edge of the bank as represented by Zone B.

An important feature to note about FIGURE 2 is the fact that the temperature in Zone D falls off from T (the temperature of the steam bank) to a lower temperature T T the temperature at well 10, will be essentially the temperature of the fluids injected into reservoir 12 after the steam. The nature and slope of the temperature gradient within Zone D may vary considerably, as explained earlier, depending upon the temperature and type of injected gas, the amount of steam condensate left by the steam bank, and the presence or absence of liquids within the injected gas.

In traveling from well 10 to well 11, the heat content defined or contained within the envelope 14- will gradually decrease. This decrease is caused largely by heat losses to the strata 13 surrounding the reservoir 12. It will be apparent, however, that the heat lost from this envelope is far less than that which would be lost by a continuous steam drive.

As stated earlier in this description, gas injected after a bank of steam or hot liquid water should be at a pressure somewhat greater than the saturation pressure of water at the temperature within the heated portion of the reservoir. Thus, referring to the example where a reservoir has been heated with 1800 p.s.i. steam to a temperature of 621 F., gas may be injected at a pressure of 1900 p.s.i. absolute. In this case, since the vapor pressure of the residual water is 1800 p.s.i. absolute, and since the total system pressure is 1900 p.s.i. absolute, the gas partial pressure will be p.s.i. Under these circumstances, a very small quantity of a gas such as methane will move or carry considerable quantities of water vapor. Thus, a cubic foot mixture of methane and water vapor will contain about 4.6 pounds of water and 014 pound of methane; and it will carry about 4-800 B.t.u.s per cubic foot. This heat will be available to heat the cool reservoir ahead of the hot zone. By comparison, a cubic foot of injected steam at 1800 p.s.i. absolute will carry ahead about 4750 B.t.u.sthe comparison being made at an assumed reservoir temperature of 151 F It will be apparent from this comparison that methane itself carrier very little heat ahead as sensible heat.

The advantages to be derived by the practice of this invention are several, and they will be apparent upon examination. A first major advantage lies in the fact that the injection of a hot aqueous fluid need not be continued throughout the duration of a recovery operation. Instead, the injection of this fluid may be terminated as soon as enough of the fluid has been injected so as to provide a sufficiently large hot zone to permit propagation of a hot bank, with time-dependent heat loss or dissipation, to the production end of the system. The savings in the amount of steam as a result of this factor alone may constitute 20 to 50 percent of the heat consumption experienced by conventional steam or hot-water processes. Savings depend again on specific reservoir conditions. Additional quantities of heat are also saved by virtue of the fact that losses to surrounding strata are minimized in the process of this invention as contrasted to conventional processes. The smaller size of the heated zone is largely responsible for this latter saving.

As indicated earlier in this description, the peak temperature of the heat bank or zone used in the process of this invention 'will decrease gradually during the process. Since it is a prime object of the invention to inject gas at a pressure such that the resulting gas-water vapor mixture is rich in water vapor, it is desirable to decrease the pressure of the gas concurrently with any decrease in the peak temperature of the hot bank. In this connection, it will be noted that the temperature of the hot bank may be determined and followed in various ways. For example, observation wells may be employed for this purpose. It should also be noted that the intentional decrease in the pressure of the driving gas to compensate for the decrease in the peak temperature of the heat bank will not have any substantial adverse effect upon the production rate, since the pressure drop will normally occur at a time when the production rate of oil is increasing for constant-pressure operation.

The invention claimed is:

1. In a secondary recovery method of recovering oil from the producing section of an oil-bearing reservoir which underlies a unit flooding pattern of wells for the reservoir, wherein said pattern includes at least one input well and one output well, and wherein said method includes the steps of injecting an aqueous fluid into said section through each input Well in said pattern and withdrawing oil through each output well in said pattern, the improvement which comprises injecting said aqueous fluid at a temperature greater than the temperature of said producing section and in a quantity suflicient to heat from 0.2 to 0.6 of said section to the temperature of said injected fluid, reducing the pressure of said section as may be necessary to a pressure not greater than the saturation pressure of Water at the temperature of said injected fluid, injecting a gas which is substantially inert to said oil into said section through each input. well in said pattern to drive said injected aqueous fluid toward each output well in said pattern, also injecting cool Water through each said input well into said section after the injection of said fluid and before the injection of said gas is terminated, the quantity of water injected being 7 H 8 sufiicient to cool the portions of said section from which 4. A method as defined in claim 2 in which said fluid said injected fluid is driven by said gas and also to prois hot liquid Water.

vide said portions with adequate permeability to Water. 2. A method as defined in claim 1 in which the hot aqueous fluid has a temperature between 350 F. and

References Cited in the file of this patent UNITED STATES PATENTS 2,584,606 Menriam et al. Feb. 5, 1952 3. A method as defined in claim 2 in which said fluid 2,642,943 Smith et a1. June 23, 1953 is saturated steam. 2,788,071 Pelzer Apr. 9, 1957 

